Liquid sample extraction and vaporization analysis in chemical and petrochemical processing is well-known and well-established. Vaporized samples extracted from a source are used for processing control, pollution monitoring, purity analysis, energy content auditing, etc. In such cases, it is important that the constituents of the vaporized sample correspond to the composition of the extracted sample. In the case of a natural gas pipeline for energy audit purposes, it is desirable to conduct sample analysis extraction at custody transfer points along the gas distribution pathway, e.g., at the wellhead, at compression into liquid, at injection into a main pipeline, at regasification, etc.
It is well documented that the natural gas industry has experienced rapid growth and generated a significant need for field deployable analyzing capabilities. For example, in the United States alone, shale oil & gas extraction activities in the Marcellus Formation, Eagle Ford, and Bakken deposits have generated numerous new drilling fields, pipeline injection and gathering points and custody transfer points that are remotely-sited from conventional infrastructure, e.g. sources of electric power and telemetric communication. Consequently, sample take-off and analyzing operations at such points are curtailed if not altogether prevented unless a temporary source of electrical power and communication is provided.
To this end, the natural gas industry has turned in some instances to conventional gas or diesel powered electric generators for powering sample takeoff and analyzing equipment. However, reliance on such generators, itself, creates logistical and maintenance issues. First, there is the need for regular resupply of the generator fuel in addition to the requirement for engine maintenance both of which require vehicular road access to the site of the analyzing equipment. One known solution to overcome to reliance on such power generation methods where the pipeline product involved is natural gas involves tapping directly into the pipeline and extracting natural gas for a natural gas (NG) powered generator. One significant drawback from such an arrangement is the need for construction of an independent pipeline takeoff connection to the generator. In an NG environment, specially trained technicians are required for such installations. Subsequently, if a conventional power source such as an overland power line becomes available, the takeoff connection must either be deactivated or removed.
Consequently, when a new extraction field is developed remote from power and telephone lines, either at least one new line must be strung with its concomitant adverse environmental impact or multiple generator units need to be transported, positioned, maintained and fueled to power a discrete array of analyzer units various flow control and conditioning equipment, analyzers, communication and computer control units associated with the extraction. At a cost, presently at about $75,000 (50,000) for each installation, reliance on such electrical generator units can result in substantial unrecoverable costs.
A further consideration results from the extraction of a “Wet” gas from wells. Although natural gases obtained from wells are predominantly methane, certain shale-derived gases comprise a significant amount of C2 to C5 hydrocarbons and up to C8 hydrocarbon constituents—“heavies”. “Dry” gas, containing minimal “heavies” is not significantly affected by differential temperature and pressure within the pipeline and/or at the regulator inlet and outlet. However, “Wet” gas characteristically includes a significant proportion of “heavies” which leads to dew point dropout/phase transition in cases of fluctuating temperature and pressure. For example, liquid pressure diminishes upon removal from the pipeline stream at take-off and during transit to an analyzer unit. Such fluctuations induce partitioning of the heavies whether in a liquid or vapor phase. It is therefore important to maintain consistent sample temperature and pressures regardless of the sample phase during the entire duration of transit from take-off to vaporizer and from vaporizer to analyzer.
Liquid intrusion into an analyzing system is unacceptable to the extent that the present ISO 8943 standard requires restriction of liquid flow to the conditioning vaporizer in order to prevent flooding of the system. The conventional approach to satisfy this requirement is to incorporate a flow restrictor. However, if the sample is a “Wet” NG, an in-line flow restrictor will induce in-line pressure changes causing partitioning/flashing of the heavies into discernable fractions. That is, the lights partition from the heavy components where the lighter constituents pass first into the vaporizer before the heavies. The presence of the differently-constituted fractions skews the accuracy of the content analysis which implicates the accuracy of the energy content measurements. Where such partitioning is combined because of inconsistent temperature and pressure, a phase transition curve may be violated inducing Joules-Thompson condensation of the partitioned vapor into a liquid phase. In the case of a system using a gas chromatograph (GC) for analysis, injection of a liquid into a GC will damage the analyzer.
Therefore, a need exists for an integrated sample take-off, analytical system that is self-powering, easily transportable, capable of two-way telemetry, and provides low-power sample take-off conditioning to an associated low-power analyzer that minimizes risk of vapor sample phase partition and condensation or transition. The system preferably also meets regulatory and safety requirements while being field deployable, particularly in the case of newly-established “wet” natural gas extraction resources and transfer points remotely located from conventional infrastructure.